Methods for treating a subterranean formation with a curable composition using a jetting tool

ABSTRACT

A method of treating a subterranean formation is provided, the method comprising the steps of: positioning a jetting tool in a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; and delivering a curable composition through the jetting tool and to the formation, wherein the curable composition: cures to form a solid substance or a semi-solid, gel-like substance, and is a fluid having a sufficiently low viscosity to penetrate into the formation. The methods according to the invention are particularly suited for treating weakly consolidated or unconsolidated formations with a hardenable resin composition to help consolidate the formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

TECHNICAL FIELD

This invention relates generally to improvements in methods that are used to stimulate hydrocarbon (e.g., oil & gas) production from a subterranean formation penetrated by a wellbore. More particularly, this invention relates to methods of treating a subterranean formation using a jetting tool.

BACKGROUND

U.S. Pat. No. 5,249,628 issued Oct. 5, 1993, having for named inventor Jim B. Surjaatmadja, and filed on Sep. 29, 1992 discloses casing slip joints provided on opposite sides of a fracture initiation location to accommodate casing and formation movement during fracturing of a well. In another aspect of the invention, the fracture initiation location is provided by forming openings through the well casing and then forming fan-shaped slots in the formation surrounding the casing. Those slots are formed by a hydraulic jet which is directed through the opening and then pivoted generally about the point of the opening. These fan-shaped slots circumscribe an angle about the axis of the casing substantially greater than the angle circumscribed by the opening itself through which the slot was formed. These techniques are particularly applicable to fracturing of horizontal wells. See U.S. Pat. No. 5,249,628, Abstract. The entirety of U.S. Pat. No. 5,249,628 is incorporated herein by reference.

U.S. Pat. No. 5,361,856 issued Nov. 8, 1994, having for named inventors Jim B. Surjaatmadja, Steven L. Holden, and David D. Szarka, and filed on Sep. 9, 1993, discloses a well jetting apparatus for use in fracturing of a well. Fracture initiation is provided by forming openings through the well casing and then forming fan-shaped slots in the formation surrounding the casing. Those slots are formed by the jetting apparatus which has at least one hydraulic jet directed through the opening. The apparatus may be pivoted generally about the point of the opening to form the slots, but preferably a plurality of slots are formed substantially simultaneously. These fan-shaped slots circumscribe an angle about the axis of the casing substantially greater than the angle circumscribed by the opening itself through which the slot was formed. These techniques are particularly applicable to fracturing of horizontal wells, but the apparatus may be used in any well configuration. See U.S. Pat. No. 5,361,856, Abstract. The entirety of U.S. Pat. No. 5,361,856 is incorporated herein by reference.

U.S. Pat. No. 5,765,642 issued Jun. 16, 1998, having for named inventor Jim B. Surjaatmadja, and filed on Dec. 23, 1996 discloses methods of fracturing a subterranean formation, which basically comprise positioning a hydrajetting tool having at least one fluid jet forming nozzle in the well bore adjacent the formation to be fractured and jetting fluid through the nozzle against the formation at a pressure sufficient to form a fracture in the formation. See U.S. Pat. No. 5,765,642, Abstract. The entirety of U.S. Pat. No. 5,765,642 is incorporated herein by reference.

U.S. Pat. No. 6,776,236 issued Aug. 17, 2004, having for named inventor Phillip D. Nguyen, and filed on Oct. 16, 2002, discloses methods of completing unconsolidated hydrocarbon producing zones penetrated by cased and cemented well bores. The methods include the steps of forming spaced openings through the casing and cement and injecting a first hardenable resin composition through the openings into the unconsolidated producing zone adjacent to the well bore. Without waiting for the first hardenable resin composition to harden, a fracturing fluid containing proppant particles coated with a second hardenable resin composition is injected through the openings into the unconsolidated producing zone at a rate and pressure sufficient to fracture the producing zone. The proppant particles coated with the second hardenable resin composition are deposited in the fractures and the first and second hardenable resin compositions are allowed to harden by heat. See U.S. Pat. No. 6,776,236, Abstract. The entirety of U.S. Pat. No. 6,776,236 is incorporated herein by reference.

SUMMARY OF THE INVENTION

According to the invention, a method of treating a subterranean formation, is provided, the method comprising the steps of: positioning a jetting tool in a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; and delivering a curable composition through the jetting tool and to the formation, wherein at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation.

According to another aspect of the invention, a method of treating a subterranean formation is provided, the method comprising the steps of: isolating an interval of the wellbore penetrating the subterranean formation; positioning a jetting tool in the isolated interval of the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation; and delivering a curable composition through the jetting tool and to the formation, wherein at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation.

According to yet another aspect of the invention, a method of treating a subterranean formation is provided, wherein the formation is weakly consolidated or unconsolidated, the method comprising the steps of: positioning a jetting tool a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation; and delivering a curable composition through the jetting tool and to the formation, wherein at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation.

Therefore, from the foregoing, it is a general object of the present invention to provide improved methods for treating a formation including the use of a jetting tool and for delivering a curable composition through the jetting tool. Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art when the following description of the preferred embodiments is read in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic diagram illustrating a jetting tool creating perforation tunnels through an uncased horizontal wellbore in a first zone of a subterranean formation.

FIG. 1B is a schematic diagram illustrating a jetting tool creating perforation tunnels through a cased horizontal wellbore in a first zone of a subterranean formation.

FIG. 2 is a schematic diagram illustrating a cross-sectional view of the jetting tool shown in FIG. 1 forming four equally spaced perforation tunnels in the first zone of the subterranean formation.

FIG. 3 is a schematic diagram illustrating the creation of fractures in the first zone by the jetting tool wherein the plane of the fracture(s) is perpendicular to the wellbore axis.

FIGS. 4A and 4B illustrate operation of a jetting tool for use in carrying out the methods according to the present invention.

DETAILED DESCRIPTION

As used herein and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or parts of an assembly, subassembly, or structural element.

If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

In general, the invention according to the present invention provides a method of treating a subterranean formation, the method comprising the steps of: positioning a jetting tool in a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; and delivering a curable composition through the jetting tool and to the formation, wherein at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation. The low viscosity fluid can be obtained by thinning down higher viscosity fluids using solvents.

Preferably, the viscosity is sufficiently low that no substantial amount of residue remains behind filling the pore spaces of the formation as the curable composition penetrates into the formation. This allows the placement of the curable composition to be better controlled and without undesired effects on the permeability of the formation.

The low-viscosity curable composition is capable of penetrating the subterranean formation at relatively low flow rate and pressure differential. For example, the delivery rate through the jetting tool and to the formation would typically be less than about 2 barrels per minute.

Even when the method is used to treat a proppant pack in a fracture in a subterranean formation or a gravel pack adjacent the formation, the curable composition should have a sufficiently low viscosity to penetrate into the formation. This avoids risking any substantial plugging of the permeability of the surrounding formation.

Regardless of the type of curable composition chosen for use in treating a subterranean formation, the viscosity of the curable composition should be sufficiently low to be able to penetrate into the subterranean formation. For example, for a weakly consolidated or unconsolidated formation, the viscosity should be sufficient low to penetrate into the rock of the formation.

To achieve the desired penetration, the apparent viscosity of the curable composition is preferably below about 100 centipoise (“cP”), more preferably below about 50 cP, and most preferably below about 10 cP. The apparent viscosity is preferably measured within the range of the bottom hole static temperature (“BHST”) of the subterranean formation. More preferably, the apparent viscosity of the curable composition is measured at the lower limit of the bottom hole static temperature of the subterranean formation. Achieving the desired viscosity will generally involve either the use of a solvent, although the use of heat can be used to reduce the viscosity of the chosen curable composition.

Factors that may influence the amount of solvent needed include the geographic location of the well and the surrounding environmental conditions. In some embodiments, suitable consolidating fluid-to-solvent ratios range from about 1:0.2 to about 1:20. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine a sufficient amount of a suitable solvent to achieve the desired viscosity and, thus, to achieve the preferred penetration into the subterranean formation. Placement or mixing of the solvents can be done uphole (on surface) or can be performed in situ (downhole). This can be achieved by taking advantage of the annular passages, or a second tubular system downhole.

The method is particularly useful where the formation is a weakly consolidated or unconsolidated formation. In such a situation, the curable composition is preferably a hardenable resin composition.

For consolidation applications, in which case the curable compositions are sometimes referred to as consolidation fluids, suitable resins include all resins know in the art that are capable of forming a hardened, consolidated mass. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins include two component epoxy based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped down hole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.), but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing. Again, this does not preclude the ability of mixing the catalysts downhole when so desired.

Selection of a suitable resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced. By way of example, for subterranean formations having a bottom hole static temperature (“BHST”) ranging from about 60° F. to about 250° F., two-component epoxy-based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred. For subterranean formations having a BHST ranging from about 300° F. to about 600° F., a furan-based resin may be preferred. For subterranean formations having a BHST ranging from about 200° F. to about 400° F., either a phenolic-based resin or a one-component HT epoxy-based resin may be suitable. For subterranean formations having a BHST of at least about 175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin may also be suitable.

Any solvent that is compatible with the chosen resin and achieves the desired viscosity effect is suitable for use in the present invention. Some preferred solvents are those having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formanide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d'limonene, fatty acid methyl esters, and combinations thereof. Other preferred solvents include aqueous dissolvable solvents such as, methanol, isopropanol, butanol, glycol ether solvents, and combinations thereof. Suitable glycol ether solvents include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanol containing at least one C₁ to C₆ alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an appropriate solvent is dependent on the resin chosen and is within the ability of one skilled in the art with the benefit of this disclosure.

One resin-type coating material suitable for use in the methods of the present invention is a two-component epoxy based resin comprising a hardenable resin component and a hardening agent component. The hardenable resin component is comprised of a hardenable resin and an optional solvent. The solvent may be added to the resin to reduce its viscosity for ease of handling, mixing and transferring. It is within the ability of one skilled in the art with the benefit of this disclosure to determine if and how much solvent may be needed to achieve a viscosity suitable to the subterranean conditions. Factors that may affect this decision include geographic location of the well and the surrounding weather conditions. An alternate way to reduce the viscosity of the liquid hardenable resin is to heat it. This method avoids the use of a solvent altogether, which may be desirable in certain circumstances. The second component is the liquid hardening agent component, which is comprised of a hardening agent, a silane coupling agent, a surfactant, an optional hydrolyzable ester for, among other things, breaking gelled fracturing fluid films on the proppant particles, and an optional liquid carrier fluid for, among other things, reducing the viscosity of the liquid hardening agent component. It is within the ability of one skilled in the art with the benefit of this disclosure to determine if and how much liquid carrier fluid is needed to achieve a viscosity suitable to the subterranean conditions.

Examples of hardenable resins that can be used in the hardenable resin component include, but are not limited to, organic resins such as bisphenol A diglycidyl ether resin, butoxymethyl butyl glycidyl ether resin, bisphenol A-epichlorohydrin resin, polyepoxide resin, novolak resin, polyester resin, phenol-aldehyde resin, urea-aldehyde resin, furan resin, urethane resin, a glycidyl ether resin, and combinations thereof. The hardenable resin used is included in the hardenable resin component in an amount in the range of from about 60% to about 100% by weight of the hardenable resin component. In some embodiments the hardenable resin used is included in the hardenable resin component in an amount of about 70% to about 90% by weight of the hardenable resin component.

Any solvent that is compatible with the hardenable resin and achieves the desired viscosity effect is suitable for use in the hardenable resin component of the integrated consolidation fluids of the present invention. Some preferred solvents are those having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d'limonene, fatty acid methyl esters, and combinations thereof. Other preferred solvents include aqueous dissolvable solvents such as, methanol, isopropanol, butanol, glycol ether solvents, and combinations thereof. Suitable glycol ether solvents include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol containing at least one C₁ to C₆ alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an appropriate solvent is dependent on the resin composition chosen and is within the ability of one skilled in the art with the benefit of this disclosure.

As described above, use of a solvent in the hardenable resin component is optional but may be desirable to reduce the viscosity of the hardenable resin component for ease of handling, mixing, and transferring. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine if and how much solvent is needed to achieve a suitable viscosity. In some embodiments the amount of the solvent used in the hardenable resin component is in the range of from about 0.1% to about 30% by weight of the hardenable resin component. Optionally, the hardenable resin component may be heated to reduce its viscosity, in place of, or in addition to, using a solvent.

Examples of the hardening agents that can be used in the liquid hardening agent component of the two-component consolidation fluids of the present invention include, but are not limited to, piperazine, derivatives of piperazine (e.g., aminoethylpiperazine), 2H-pyrrole, pyrrole, imidazole, pyrazole, pyridine, pyrazine, pyrimidine, pyridazine, indolizine, isoindole, 3H-indole, indole, 1H-indazole, purine, 4H-quinolizine, quinoline, isoquinoline, phthalazine, naphthyridine, quinoxaline, quinazoline, 4H-carbazole, carbazole, β-carboline, phenanthridine, acridine, phenathroline, phenazine, imidazolidine, phenoxazine, cinnoline, pyrrolidine, pyrroline, imidazoline, piperidine, indoline, isoindoline, quinuclindine, morpholine, azocine, azepine, 2H-azepine, 1,3,5-triazine, thiazole, pteridine, dihydroquinoline, hexa methylene imine, indazole, amines, aromatic amines, polyamines, aliphatic amines, cyclo-aliphatic amines, amides, polyamides, 2-ethyl-4-methyl imidazole, 1,1,3-trichlorotrifluoroacetone, and combinations thereof. The chosen hardening agent often effects the range of temperatures over which a hardenable resin is able to cure. By way of example and not of limitation, in subterranean formations having a temperature from about 60° F. to about 250° F., amines and cyclo-aliphatic amines such as piperidine, triethylamine, N,N-dimethylaminopyridine, benzyldimethylamine, tris(dimethylaminomethyl) phenol, and 2-(N2N-dimethylaminomethyl)phenol are preferred with N,N-dimethylaminopyridine most preferred. In subterranean formations having higher temperatures, 4,4′-diaminodiphenyl sulfone may be a suitable hardening agent. Hardening agents that comprise piperazine or a derivative of piperazine have been shown capable of curing various hardenable resins from temperatures as low as about 70° F. to as high as about 350° F. The hardening agent used is included in the liquid hardening agent component in an amount sufficient to consolidate the coated particulates. In some embodiments of the present invention, the hardening agent used is included in the liquid hardenable resin component in the range of from about 40% to about 60% by weight of the liquid hardening agent component. In some embodiments the hardenable resin used is included in the hardenable resin component in an amount of about 45% to about 55% by weight of the liquid hardening agent component.

The silane coupling agent may be used, among other things, to act as a mediator to help bond the resin to formation particulates and-or proppant. Examples of suitable silane coupling agents include, but are not limited to, N-β-(aminoethyl)-γ-aminopropyl trimethoxysilane, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, 3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silane coupling agent used is included in the liquid hardening agent component in an amount capable of sufficiently bonding the resin to the particulate. In some embodiments of the present invention, the silane coupling agent used is included in the liquid hardenable resin component in the range of from about 0.1% to about 3% by weight of the liquid hardening agent component.

Any surfactant compatible with the hardening agent and capable of facilitating the coating of the resin onto particles in the subterranean formation may be used in the hardening agent component of the integrated consolidation fluids of the present invention. Such surfactants include, but are not limited to, an alkyl phosphonate surfactant (e.g., a Cl₂-C₂₂ alkyl phosphonate surfactant), an ethoxylated nonyl phenol phosphate ester, one or more cationic surfactants, and one or more nonionic surfactants. Mixtures of one or more cationic and nonionic surfactants also may be suitable. Examples of such surfactant mixtures are described in U.S. Pat. No. 6,311,773 issued to Todd et al. on Nov. 6, 2001, the relevant disclosure of which is incorporated herein by reference. The surfactant or surfactants used are included in the liquid hardening agent component in an amount in the range of from about 1% to about 10% by weight of the liquid hardening agent component.

While not required, examples of hydrolysable esters that can be used in the hardening agent component of the integrated consolidation fluids of the present invention include, but are not limited to, a mixture of dimethylglutarate, dimethyladipate, and dimethylsuccinate; sorbitol; catechol; dimethylthiolate; methyl salicylate; dimethyl salicylate; dimethylsuccinate; ter-butylhydroperoxide; and combinations thereof. When used, a hydrolyzable ester is included in the hardening agent component in an amount in the range of from about 0.1% to about 3% by weight of the hardening agent component. In some embodiments a hydrolysable ester is included in the hardening agent component in an amount in the range of from about 1% to about 2.5% by weight of the hardening agent component.

Use of a diluent or liquid carrier fluid in the hardenable resin composition is optional and may be used to reduce the viscosity of the hardenable resin component for ease of handling, mixing and transferring. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine if and how much liquid carrier fluid is needed to achieve a viscosity suitable to the subterranean conditions. Any suitable carrier fluid that is compatible with the hardenable resin and achieves the desired viscosity effects is suitable for use in the present invention. Some preferred liquid carrier fluids are those having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d'limonene, fatty acid methyl esters, and combinations thereof. Other preferred liquid carrier fluids include aqueous dissolvable solvents such as, methanol, isopropanol, butanol, glycol ether solvents, and combinations thereof. Suitable glycol ether liquid carrier fluids include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanol containing at least one C₁ to C₆ alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an appropriate liquid carrier fluid is dependent on the resin composition chosen and is within the ability of one skilled in the art with the benefit of this disclosure.

Another type of resin suitable for use in the methods of the present invention is a furan-based resin. Suitable furan-based resins include, but are not limited to, furfuryl alcohol resins, mixtures furfuryl alcohol resins and aldehydes, and a mixture of furan resins and phenolic resins. Of these, furfuryl alcohol resins are preferred. A furan-based resin may be combined with a solvent to control viscosity if desired. Suitable solvents for use in the furan-based consolidation fluids of the present invention include, but are not limited to 2-butoxy ethanol, butyl lactate, butyl acetate, tetrahydrofurfuryl methacrylate, tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinic acids,and furfuryl acetate. Of these, 2-butoxy ethanol is preferred.

Still another type of resin suitable for use in the methods of the present invention is a phenolic-based resin. Suitable phenolic-based resins include, but are not limited to, terpolymers of phenol, phenolic formaldehyde resins, and a mixture of phenolic and furan resins. Of these, a mixture of phenolic and furan resins is preferred. A phenolic-based resin may be combined with a solvent to control viscosity if desired. Suitable solvents for use in the phenolic-based consolidation fluids of the present invention include, but are not limited to butyl acetate, butyl lactate, furfuryl acetate, and 2-butoxy ethanol. Of these, 2-butoxy ethanol is preferred.

Another type of resin suitable for use in the methods of the present invention is a HT epoxy-based resin. Suitable HT epoxy-based components include, but are not limited to, bisphenol A-epichlorohydrin resins, polyepoxide resins, novolac resins, polyester resins, glycidyl ethers and mixtures thereof. Of these, bisphenol A-epichlorohydrin resins are preferred. An HT epoxy-based resin may be combined with a solvent to control viscosity if desired. Suitable solvents for use with the HT epoxy-based resins of the present invention are those solvents capable of substantially dissolving the HT epoxy-resin chosen for use in the consolidation fluid. Such solvents include, but are not limited to, dimethyl sulfoxide and dimethyl formamide. A co-solvent such as a dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethylene glycol methyl ether, ethylene glycol butyl ether, diethylene glycol butyl ether, propylene carbonate, d'limonene and fatty acid methyl esters, may also be used in combination with the solvent.

Yet another resin-type coating material suitable for use in the methods of the present invention is a phenol/phenol formaldehyde/furfuryl alcohol resin comprising from about 5% to about 30% phenol, from about 40% to about 70% phenol formaldehyde, from about 10 to about 40% furfuryl alcohol, from about 0.1% to about 3% of a silane coupling agent, and from about 1% to about 15% of a surfactant. In the phenol/phenol formaldehyde/furfuryl alcohol resins suitable for use in the methods of the present invention, suitable silane coupling agents include, but are not limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, 3-glycidoxypropyltrimethoxysilane, and n-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane. Suitable surfactants include, but are not limited to, an ethoxylated nonyl phenol phosphate ester, mixtures of one or more cationic surfactants, and one or more non-ionic surfactants and an alkyl phosphonate surfactant.

Gelable compositions suitable for use in the present invention include those compositions that cure to form a semi-solid, gel-like substance. The gelable composition may be any gelable liquid composition capable of converting into a gelled substance capable of substantially consolidating the formation while allowing the formation to remain flexible. As referred to herein, the term “flexible” refers to a state wherein the treated portion of the formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation. Thus, the resultant gelled substance stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling. As a result, the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the treated portion. Examples of suitable gelable liquid compositions include, but are not limited to, (1) gelable resin compositions, (2) gelable aqueous silicate compositions, (3) crosslinkable aqueous polymer compositions, and (4) polymerizable organic monomer compositions.

Certain embodiments of the gelable liquid compositions of the present invention comprise gelable resin compositions that cure to form flexible gels. Unlike the hardenable resin compositions described above, which cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances between the particulates of the treated zone of the unconsolidated formation. Gelable resin compositions allow the treated portion of the formation to remain flexible and resist breakdown.

Generally, the gelable resin compositions useful in accordance with this invention comprise a curable resin, a diluent, and a resin curing agent. When certain resin curing agents, such as polyamides, are used in the curable resin compositions, the compositions form the semi-solid, gelled substances described above. Where the resin curing agent used may cause the organic resin compositions to form hard, brittle material rather than a desired gelled substance, the curable resin compositions may further comprise one or more “flexibilizer additives” (described in more detail below) to provide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present invention include, but are not limited to, organic resins such as polyepoxide resins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.

Any diluent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of diluents that may be used in the gelable resin compositions of the present invention include, but are not limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some embodiments of the present invention, the diluent comprises butyl lactate. The diluent may be used to reduce the viscosity of the gelable resin composition. Among other things, the diluent acts to provide flexibility to the cured composition. The diluent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect. Subject to providing the desired viscosity effect, generally, the diluent used is included in the gelable resin composition in amount in the range of from about 5% to about 75% by weight of the curable resin.

Generally, any resin curing agent that may be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent chosen is an amide or a polyamide, generally no flexibilizer additive will be required because, among other things, such curing agents cause the gelable resin composition to convert into a semi-solid, gelled substance. Other suitable resin curing agents (such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art) will tend to cure into a hard, brittle material and will thus benefit from the addition of a flexibilizer additive. Generally, the resin curing agent used is included in the gelable resin composition, whether a flexibilizer additive is included or not, in an amount in the range of from about 5% to about 75% by weight of the curable resin. In some embodiments of the present invention, the resin curing agent used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.

As noted above, flexibilizer additives may be used, among other things, to provide flexibility to the gelled substances formed from the curable resin compositions. Flexibilizer additives may be used where the resin curing agent chosen would cause the gelable resin composition to cure into a hard and brittle material—rather than a desired gelled substance. For example, flexibilizer additives may be used where the resin curing agent chosen is not an amide or polyamide. Examples of suitable flexibilizer additives include, but are not limited to, an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as dibutyl phthalate, are preferred. Where used, the flexibilizer additive may be included in the gelable resin composition in an amount in the range of from about 5% to about 80% by weight of the gelable resin. In some embodiments of the present invention, the flexibilizer additive may be included in the curable resin composition in an amount in the range of from about 20% to about 45% by weight of the curable resin.

In other embodiments, the gelable liquid compositions of the present invention may comprise a gelable aqueous silicate composition. Generally, the gelable aqueous silicate compositions that are useful in accordance with the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.

The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally comprise an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution generally may be fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate. Of these, sodium silicate is preferred. While sodium silicate exists in many forms, the sodium silicate used in the aqueous alkali metal silicate solution preferably has a Na₂O-to-SiO₂ weight ratio in the range of from about 1:2 to about 1:4. Most preferably, the sodium silicate used has a Na₂O-to-SiO₂ weight ratio in the range of about 1:3.2. Generally, the alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount in the range of from about 0.1% to about 10% by weight of the aqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueous silicate compositions is used, among other things, to convert the gelable aqueous silicate compositions into the desired semi-solid, gel-like substance described above. Selection of a temperature-activated catalyst is related, at least in part, to the temperature of the subterranean formation to which the gelable aqueous silicate composition will be introduced. The temperature-activated catalysts that can be used in the gelable aqueous silicate compositions of the present invention include, but are not limited to, ammonium sulfate (which is most suitable in the range of from about 60° F. to about 240° F.); sodium acid pyrophosphate (which is most suitable in the range of from about 60° F. to about 240° F.); citric acid (which is most suitable in the range of from about 60° F. to about 120° F.); and ethyl acetate (which is most suitable in the range of from about 60° F. to about 120° F.). Generally, the temperature-activated catalyst is present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.

In other embodiments, the gelable liquid compositions of the present invention comprise crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent. Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of the present invention, they are not exposed to breakers or de-linkers and so they retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which the crosslinkable composition and the crosslinking agent may be dissolved, mixed, suspended, or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, and carboxylate-containing terpolymers and tetrapolymers of acrylate. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers that may be used in the crosslinkable aqueous polymer compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable aqueous polymer composition in an amount sufficient to form the desired gelled substance in the subterranean formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous solvent. In another embodiment of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV.

The crosslinking agent should be present in the crosslinkable aqueous polymer compositions of the present invention in an amount sufficient to provide, among other things, the desired degree of crosslinking. In some embodiments of the present invention, the crosslinking agent is present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 0.01% to about 5% by weight of the crosslinkable aqueous polymer composition. The exact type and amount of crosslinking agent or agents used depends upon the specific crosslinkable polymer to be crosslinked, formation temperature conditions, and other factors known to those individuals skilled in the art.

Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent derived from guar, guar derivatives, or cellulose derivatives. The crosslinking delaying agent may be included in the crosslinkable aqueous polymer compositions, among other things, to delay crosslinking of the crosslinkable aqueous polymer compositions until desired. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.

In other embodiments, the gelled liquid compositions of the present invention comprise polymerizable organic monomer compositions. Generally, suitable polymerizable organic monomer compositions comprise an aqueous-base fluid, a water-soluble polymerizable organic monomer, an oxygen scavenger, and a primary initiator.

The aqueous-based fluid component of the polymerizable organic monomer composition generally may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. Preferably, the water-soluble polymerizable organic monomer should be self-crosslinking. Examples of suitable monomers which are self crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylaamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate is preferred. An example of a particularly preferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where a mixture thereof is used) should be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelled substance after placement of the polymerizable organic monomer composition into the subterranean formation. In some embodiments of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous-base fluid. In another embodiment of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer composition may inhibit the polymerization process of the water-soluble polymerizable organic monomer or monomers. Therefore, an oxygen scavenger, such as stannous chloride, may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it may be readily combined with the polymerizable organic monomer composition on the fly, the stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, the stannous chloride may be dissolved in a 0.1% by weight aqueous hydrochloric acid solution in an amount of about 10% by weight of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be included in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, the stannous chloride may be included in the polymerizable organic monomer composition of the present invention in an amount in the range of from about 0.005% to about 0.1% by weight of the polymerizable organic monomer composition.

The primary initiator is used, among other things, to initiate polymerization of the water-soluble polymerizable organic monomer(s) used in the present invention. Any compound or compounds that form free radicals in aqueous solution may be used as the primary initiator. The free radicals act, among other things, to initiate polymerization of the water-soluble polymerizable organic monomer present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems employing reducing agents, such as sulfites in combination with oxidizers; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2′-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2′-azobis (2-aminopropane), 4,4′-azobis (4-cyanovaleric acid), and 2,2′-azobis (2-methyl-N-(2-hydroxyethyl) propionamide. Generally, the primary initiator should be present in the polymerizable organic monomer composition in an amount sufficient to initiate polymerization of the water-soluble polymerizable organic monomer(s). In certain embodiments of the present invention, the primary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s). One skilled in the art will recognize that as the polymerization temperature increases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further may comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed into a subterranean formation that is relatively cool as compared to the surface mixing, such as when placed below the mud line in offshore operations. The secondary initiator may be any suitable water-soluble compound or compounds that may react with the primary initiator to provide free radicals at a lower temperature. An example of a suitable secondary initiator is triethanolamine. In some embodiments of the present invention, the secondary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s).

Also optionally, the polymerizable organic monomer compositions of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally, the crosslinking agent may be present in polymerizable organic monomer compositions in an amount in the range of from 0.01% to about 5% by weight of the polymerizable organic monomer composition.

The method according to the invention can be advantageously employed for an open-hole wellbore, especially but not necessarily in the case of a weakly consolidated or unconsolidated formation. The method according to claim 1, wherein the wellbore is a cased or lined wellbore.

The method can include the step of drilling the wellbore to penetrate the formation, whereby the wellbore is an open-hole wellbore. After drilling the open-hole wellbore, the method can further comprise the step of installing a casing or liner in the open-hole wellbore to form a cased or lined wellbore. If a pre-existing open-hole wellbore is not already cased or lined, the method can include the step of installing a casing or liner in the wellbore to form a cased or lined wellbore.

The details of the method according to the present invention will now be described with reference to the accompanying drawings. First, a wellbore 10 is drilled into the subterranean formation of interest 12 using conventional (or future) drilling techniques. Next, depending upon the nature of the formation, the wellbore 10 is either left open hole, as shown in FIG. 1A, or lined with a casing string or slotted liner, as shown in FIG. 1B. The wellbore 10 may be left as an uncased open hole if, for example, the subterranean formation is highly consolidated or in the case where the well is a highly deviated or horizontal well, which are often difficult to line with casing. In cases where the wellbore 10 is lined with a casing string, the casing string may or may not be cemented to the formation. The casing in FIG. 1B is shown cemented to the subterranean formation. Furthermore, when uncemented, the casing liner may be either a slotted or preperforated liner or a solid liner. Those of ordinary skill in the art will appreciate the circumstances when the wellbore 10 should or should not be cased, whether such casing should or should not be cemented, and whether the casing string should be slotted, preperforated or solid. Indeed, the present invention does not lie in the performance of the steps of drilling the wellbore 10 or whether or not to case the wellbore, or if so, how. The method according to the invention can also be applied to an older well bore that has zones that are in need of stimulation.

Once the wellbore 10 is drilled, and if deemed necessary cased, a jetting tool 14, such as that used in the SURGIFRAC process described in U.S. Pat. No. 5,765,642, is placed into the wellbore 10 at a location of interest, e.g., adjacent to a first zone 16 in the subterranean formation 12. In one exemplary embodiment, the jetting tool 14 is attached to a tubing or coiled tubing 18, which lowers the jetting tool 14 into the wellbore 10 and supplies it with jetting fluid. Annulus 19 is formed between the tubing 18 and the wellbore 10. The jetting tool 14 then operates to form perforation tunnels 20 in the first zone 16, as shown in FIG. 1. The perforation fluid being pumped through the jetting tool 14 contains a base fluid, which is commonly water and abrasives (commonly sand). As shown in FIG. 2, four equally spaced jets (in this example) of fluid 22 are injected into the first zone 16 of the subterranean formation 12. As those of ordinary skill in the art will recognize, the jetting tool 14 can have any number of jets, configured in a variety of combinations along and around the tool.

In the next step of the well completion method according to the present invention, the first zone 16 is fractured. This may be accomplished by any one of a number of ways. In one exemplary embodiment, the jetting tool 14 injects a high pressure fracture fluid into the perforation tunnels 20. As those of ordinary skill in the art will appreciate, the pressure of the fracture fluid exiting the jetting tool 14 is sufficient to fracture the formation in the first zone 16. Using this technique, the jetted fluid forms cracks or fractures 24 along the perforation tunnels 20, as shown in FIG. 3. In a subsequent step, an acidizing fluid may be injected into the formation through the jetting tool 14. The acidizing fluid etches the formation along the cracks 24 thereby widening them.

In another exemplary embodiment, the jetted fluid carries a proppant into the cracks or fractures 24. The injection of additional fluid extends the fractures 24 and the proppant prevents them from closing up at a later time. The present invention contemplates that other fracturing methods may be employed. For example, the perforation tunnels 20 can be fractured by pumping a hydraulic fracture fluid into them from the surface through annulus 19. Next, either and acidizing fluid or a proppant fluid can be injected into the perforation tunnels 20, so as to further extend and widen them. Other fracturing techniques can be used to fracture the first zone 16.

FIGS. 4A-B illustrate the details of an example of a jetting tool 14 for use in carrying out the methods of the present invention. Jetting tool 14 comprises a main body 40, which is cylindrical in shape and formed of a ferrous metal. The main body 40 has a top end 42 and a bottom end 44. The top end 42 connects to tubing or coiled tubing 18 for operation within the wellbore 10. The main body 40 has a plurality of nozzles 46, which are adapted to direct the high pressure fluid out of the main body 40. The nozzles 46 can be disposed, and in one certain embodiment are disposed, at an angle to the main body 40, so as to eject the pressurized fluid out of the main body 40 at an angle other than 90 degrees. In other words, the fluid jet forming nozzle can be dispose at an angle other than 90° to the axis of the cylindrical main body.

The jetting tool 14 further comprises means 48 for opening the jetting tool 14 to fluid flow from the wellbore 10. Such fluid opening means 48 includes a fluid-permeable plate 50, which is mounted to the inside surface of the main body 40. The fluid-permeable plate 50 traps a ball 52, which sits in seat 54 when the pressurized fluid is being ejected from the nozzles 46, as shown in FIG. 4A. When the pressurized fluid is not being pumped down the coil tubing into the jetting tool 14, the wellbore fluid is able to be circulated up to the surface via opening means 48. More specifically, the wellbore fluid lifts the ball 52 up against fluid-permeable plate 50, which in turn allows the wellbore fluid to flow up the jetting tool 14 and ultimately up through the tubing 18 to the surface, as shown in FIG. 4B. As those of ordinary skill in the art will recognize other valves can be used in place of the ball and seat arrangement 52 and 54 shown in FIGS. 4A and 4B. Darts, poppets, and flappers. Furthermore, although FIGS. 4A and 4B only show a valve at the bottom of the jetting tool 14, such valves can be placed both at the top and the bottom, as desired.

It is to be understood, of course, that other types or variations of jetting tools can be used, for example, the jetting tools as described in each of U.S. Pat. Nos. 5,249,628; 5,361,856; and 5,765,642, each of which is incorporated by reference in its entirety.

Preferably, the step of positioning a jetting tool further comprises accessing the wellbore with coiled tubing.

The method preferably includes the step of isolating an interval of the wellbore in the subterranean formation, wherein the step of positioning a jetting tool further comprises positioning the jetting tool in the isolated interval. This allows the method to be selectively performed in a desired interval of the wellbore without affecting one or more other intervals of the wellbore.

The step of isolating an interval of the wellbore preferably includes using at least one well tool to close at least one end of the interval. The well tool for isolating an end of the interval is preferably a drillable well tool, although a removable well tool can be used. When a drillable well tool is used, the method preferably further comprises the step of further comprising the step of drilling out the drillable well tool to reopen the wellbore. The well tool for isolating an end of the interval can be, for example, a packer or bridge plug. The step of isolating the interval can also be performed dynamically, e.g. using the SurgiFrac technique to isolate the section by means of fluid velocity as explained in U.S. Pat. No. 5,765,642, which is incorporated by reference herein in its entirety.

The step of isolating an interval of the wellbore can employ using an isolation fluid to close at least one end of the interval. When an isolation fluid is used, the method preferably further comprises the step of removing the isolation fluid to reopen the wellbore.

For example, once the first zone 16 has been fractured, the present invention provides for isolating the first zone 16, so that subsequent well operations, such as the fracturing of additional zones, can be carried out without the loss of significant amounts of fluid. This isolation step can be carried out in a number of ways. In one exemplary embodiment, the isolation step is carried out by injecting into the wellbore 10 an isolation fluid, which may have a higher viscosity than the completion fluid already in the fracture or the wellbore.

In another exemplary embodiment, the isolation fluid is formed of a fluid having a similar chemical makeup as the fluid resident in the wellbore during the fracturing operation. The fluid may have a greater viscosity than such fluid, however. In one exemplary embodiment, the wellbore fluid is mixed with a solid material to form the isolation fluid. The solid material may include natural and man-made proppant agents, such as silica, ceramics, and bauxites, or any such material that has an external coating of any type. Alternatively, the solid (or semi-solid) material may include paraffin, encapsulated acid or other chemical, or resin beads.

In another exemplary embodiment, the isolation fluid is formed of a highly viscous material, such as a gel or cross-linked gel. Examples of gels that can be used as the isolation fluid include, but are not limited to, fluids with high concentration of gels such as Xanthan. Examples of cross-linked gels that can be used as the isolation fluid include, but are not limited to, high concentration gels such as Halliburton's DELTA FRAC fluids or K-MAX fluids. “Heavy crosslinked gels” could also be used by mixing the crosslinked gels with delayed chemical breakers, encapsulated chemical breakers, which will later reduce the viscosity, or with a material such as PLA (poly-lactic acid) beads, which although being a solid material, with time decomposes into acid, which will liquefy the K-MAX fluids or other crosslinked gels.

According to one aspect of the invention, the step of delivering a curable composition through the jetting tool and to the formation preferably further comprises filling the wellbore interval under sufficient pressure to force the curable composition into the formation. In this embodiment, the curable composition is delivered at a relatively slow rate through the jetting tool to merely fill the interval surrounding the jetting tool and form a bullhead. For example, the delivery rate would typically be less than about 2 barrels per minute.

According to another aspect of the invention, the step of delivering a curable composition through the jetting tool and to the formation further comprises delivering the curable composition through the jetting tool under conditions sufficient to direct and pressure the curable composition into the formation. In this embodiment, the curable composition is delivered through the jetting tool at a sufficient rate that may form a jet. Preferably, however, the step of delivering a curable composition through the jetting tool and to the formation further comprises delivering the curable composition into the formation under conditions that are not sufficient to initiate a fracture in the formation. If desired, however, the curable composition can be injected through the jetting tool under sufficient conditions to form a jet and fracture the formation.

According to yet another aspect of the invention, the method further comprises the step of injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation. The method can further comprise the step of moving the jetting tool axially and/or rotationally during the step of injecting a fracturing fluid through the jetting tool to initiate at least one fracture so as to thereby erode a straight or helical slot in a portion of the wall of the well bore.

Preferably, the step of injecting a fracturing fluid through the jetting tool to initiate at least one fracture is separate from the step of delivering a curable composition through the jetting tool and to the formation, and wherein the fracturing fluid is different than the curable composition. Preferably, the method includes performing the step of injecting a fracturing fluid through the jetting tool to initiate at least one fracture before performing the step of delivering a curable composition through the jetting tool and to the formation.

During at least part of the step of injecting a fracturing fluid through the jetting tool, the fracturing fluid preferably comprises a base fluid and a particulate material. Preferably, the viscosity of the curable composition is less than the viscosity of the base fluid. Whereas the curable composition preferably has a relatively low viscosity to allow it to move more easily into the formation rock, i.e., into and through the porosity of the formation, the base fluid of a fracturing fluid preferably has a relatively high viscosity to help suspend and carry the proppant into a fracture without prematurely settling out of the fluid. For example, the base fluid can be a gelled fluid and the particulate can be sand. A typical base fluid has an apparent viscosity of great than about 2,000 centipoise.

The method preferably further comprises the step of injecting a fracturing fluid down the annulus under conditions to sufficiently raise the fluid pressure in the annulus to extend the at least one fracture initiated by the step of injecting a fracturing fluid through the jetting tool. During at least part of the step of injecting a fracturing fluid down the annulus, the fracturing fluid preferably comprises a base fluid and a particulate material. The base fluid has high viscosity to help suspend and carry the proppant into a fracture without prematurely settling out of the fluid.

Preferably, the proppant is coated with a curable composition. Preferably, the curable composition that is used for this step of depositing a proppant coated with a curable composition into the fracture in the formation is a hardenable resin composition. If desired, and as may be preferably in certain formations containing fines, however, the proppant can be coated with a tackifying composition. It is to be understood that if desired, a portion of the proppant used in the methods according to the invention can be coated with a hardenable resin composition and another portion of the proppant can be coated with a tackifying composition.

When a hardenable resin composition is used to coat the proppant, the method of the invention preferably further comprises the step of allowing or causing the hardenable resin composition to harden before performing the step of flowing back or producing fluid from the formation. For a self-hardening resin composition, the time required for hardening will depend on the temperature of the formation. Other hardenable resin compositions may require an overflush with a fluid containing an appropriate catalyst to cause the hardenable resin composition to harden.

The curable composition that is used for the step of depositing a proppant coated with a curable composition into the fracture in the formation should have a sufficiently high viscosity to form a coating on the proppant.

In the case of practicing the method in a cased or lined wellbore, the method can further comprise the step of perforating the casing or lining. Preferably, the jetting tool is used to perforate the casing or liner. For example, for a cased or lined wellbore, the method preferably further comprises the step of injecting a perforating fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the casing or liner to form at least one perforation in the cased or lined wellbore before the step of delivering a curable composition through the jetting tool and to the formation. In such a case, the method preferably further comprises the step of injecting a fracturing fluid through the jetting tool and through the perforation under conditions sufficient to erode the wall of the well bore outside the casing or liner and to initiate at least one fracture in the formation. Although these steps can be practiced at the same time, the step of injecting a perforating fluid can be separate from the step of injecting a fracturing fluid, and the perforating fluid is not necessarily the same as the fracturing fluid.

The method according to the invention can optionally further comprise the step of overflushing the curable composition in the formation with an overflush fluid capable of displacing at least some of the curable composition farther out into the formation. This is particularly advantageous where it is desired to modify the permeability of the consolidated formation relative to that which would be obtained without the overflush. The overflush fluid is preferably an aqueous solution. The step of overflushing the curable composition further comprises: delivering the overflush fluid through the jetting tool and to the formation under conditions that are not sufficient to initiate a fracture in the formation. There may be some overlap in the introduction of overflush fluid and the curable composition, for example, in cases where separate pumping devices are used.

Preferably, the overflush fluid is placed into the formation at a matrix flow rate such that the low-viscosity resin is displaced from the channels, but is not displaced from its desired location between the formation sand particles. Generally, the volume of after-flush fluid placed in the subterranean formation ranges from about 0.1 to about 50 times the volume of the low-viscosity curable composition. In some embodiments of the present invention, the volume of overflush fluid placed in the subterranean formation ranges from about 2 to about 5 times the volume of the low-viscosity curable composition.

The method according to the invention preferably further comprise the step of flowing back or producing fluid from the formation. The method preferably further comprises the step of allowing or causing the curable composition to cure before performing the step of flowing back or producing fluid from the formation.

It is to be understood that the various steps according to preferred methods of the invention can be advantageously practiced in various combinations. It is also to be understood that the steps according to the invention and various preferred embodiments of the invention can be repeated at different intervals of the same wellbore.

EXAMPLES

An example of the steps of a method according to the invention include: for a wellbore penetrating a weakly consolidated or unconsolidated formation, isolating an interval of a wellbore from at least one other interval, for example, with at least one removable or drillable packer or with a removable or drillable bridge plug; accessing the isolated interval with tubing, preferably with coiled tubing, to position a jetting tool in the isolated interval; delivering a hardenable resin composition through the jetting tool while filling the wellbore interval and forming a bullhead of the hardenable resin composition; optionally allowing or causing the hardenable resin composition to harden to form a consolidated mass; injecting a fracturing fluid through the jetting tool under conditions sufficient to form at least one slot and to initiate a fracture in the formation; depositing a proppant coated with a hardenable resin composition in the generated fracture; optionally allowing or causing the coated proppant to harden into a consolidated mass; removing or drilling out the packer or bridge plug; and producing hydrocarbon from the formation.

Another, more preferred example of the steps of a method according to the invention include: for a wellbore penetrating a weakly consolidated or unconsolidated formation, isolating an interval of a wellbore from at least one other interval, for example, with at least one removable or drillable packer or with a removable or drillable bridge plug; accessing the isolated interval with tubing, preferably with coiled tubing, to position a jetting tool in the isolated interval; injecting a fracturing fluid through the jetting tool under conditions sufficient to form at least one slot and to initiate a fracture in the formation; depositing a proppant into the fracture; delivering a hardenable resin composition through the jetting tool while filling the wellbore interval and forming a bullhead of the hardenable resin composition; optionally allowing or causing the hardenable resin composition to harden to form a consolidated mass; removing or drilling out the packer or bridge plug; and producing hydrocarbon from the formation.

Thus, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned above as well as those inherent therein. While preferred embodiments of the invention have been described for the purpose of this disclosure, changes in the construction and arrangement of parts and the performance of steps can be made by those skilled in the art, which changes are encompassed within the spirit of this invention as defined by the appended claims. 

1. A method of treating a subterranean formation, the method comprising the steps of: a. positioning a jetting tool in a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; and b. delivering a curable composition through the jetting tool and to the formation, wherein i. at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and ii. the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation.
 2. The method according to claim 1, wherein the viscosity is sufficiently low that no substantial amount of residue remains behind filling the pore spaces of the formation as the curable composition penetrates into the formation.
 3. The method according to claim 1, wherein the apparent viscosity of the curable composition is preferably below about 100 cP.
 4. The method according to claim 3, wherein the apparent viscosity of the curable composition is measured within the range of the bottom hole static temperature of the subterranean formation.
 5. The method according to claim 4, wherein the apparent viscosity of the curable composition is measured at the lower limit of the bottom hole static temperature of the subterranean formation.
 6. The method according to claim 1, wherein the curable composition is a hardenable resin composition.
 7. The method according to claim 1, further comprising the step of: isolating an interval of the wellbore in the subterranean formation, wherein the step of positioning a jetting tool further comprises positioning the jetting tool in the isolated interval.
 8. The method according to claim 1, wherein the step of delivering a curable composition through the jetting tool and to the formation further comprises: filling the wellbore interval under sufficient pressure to force the curable composition into the formation.
 9. The method according to claim 1, wherein the step of delivering a curable composition through the jetting tool and to the formation further comprises: delivering the curable composition through the jetting tool under conditions sufficient to direct and pressure the curable composition into the formation.
 10. The method according to claim 8, wherein the step of delivering a curable composition through the jetting tool and to the formation further comprises: delivering the curable composition into the formation under conditions that are not sufficient to initiate a fracture in the formation.
 11. The method according to claim 1, further comprising the step of: injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation.
 12. The method according to claim 11, wherein the step of injecting a fracturing fluid through the jetting tool to initiate at least one fracture is separate from the step of delivering a curable composition through the jetting tool and to the formation, and wherein the fracturing fluid is different than the curable composition.
 13. The method according to claim 12, comprising performing the step of injecting a fracturing fluid through the jetting tool to initiate at least one fracture before performing the step of delivering a curable composition through the jetting tool and to the formation.
 14. The method according to claim 11, wherein during at least part of the step of injecting a fracturing fluid through the jetting tool, the fracturing fluid comprises a base fluid and a particulate material.
 15. The method according to claim 14, wherein the viscosity of the curable composition is less than the viscosity of the base fluid.
 16. The method according to claim 14, wherein the particulate material is coated with a curable composition.
 17. The method according to claim 16, wherein the curable composition that is used for the step of depositing a proppant coated with a curable composition into the fracture in the formation has a sufficiently high viscosity to form a coating on the proppant.
 18. The method according to claim 1, further comprising the step of: flowing back or producing fluid from the formation.
 19. A method of treating a subterranean formation, the method comprising the steps of: a. isolating an interval of the wellbore penetrating the subterranean formation; b. positioning a jetting tool in the isolated interval of the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; c. injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation; and d. delivering a curable composition through the jetting tool and to the formation, wherein i. at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and ii. the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation.
 20. A method of treating a subterranean formation, wherein the formation is weakly consolidated or unconsolidated, the method comprising the steps of: a. positioning a jetting tool a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; b. injecting a fracturing fluid through the jetting tool under conditions sufficient to erode a portion of the wall of the well bore and to initiate at least one fracture extending into the formation; and c. delivering a curable composition through the jetting tool and to the formation, wherein i. at least a component of the curable composition is capable of curing to form a solid substance or a semi-solid, gel-like substance, and ii. the curable composition is a fluid having a sufficiently low viscosity to penetrate into the formation. 